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Assumptions for Calculating the Installed Capacity Requirement and Related Values for the 2024-2025 Forward Capacity Auction (FCA 15)

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Assumptions for Calculating the Installed Capacity Requirement and Related Values for the 2024-2025 Forward Capacity Auction (FCA 15) JUNE 30, 2020 | WEBEX Assumptions for Calculating the Installed Capacity Requirement and Related Values for the 2024-2025 Forward Capacity Auction (FCA 15) Power Supply Planning Committee Meeting Manasa Kotha SENIOR ENGINEER, RESOURCE STUDIES AND ASSESSMENTS ISO-NE PUBLIC Objective of this Presentation • Review the assumptions used in the development of the Installed Capacity Requirement (ICR) and related values*: – Transmission Security Analysis (TSA) – Local Resource Adequacy Requirement (LRA) – Local Sourcing Requirement (LSR) – Maximum Capacity Limit (MCL) – Marginal Reliability Impact Demand Curves (MRI Demand Curves) – Hydro Quebec Installed Capability Credits (HQICCs) *The ICR, LSR, MCL, the MRI Demand Curves and HQICCs are collectively referred to as the ICR- Related Values ISO-NE PUBLIC 2 Modeling the New England Control Area for FCA 15 • The General Electric Multi-Area Reliability Simulation model (GE MARS) is used to calculate several of the ICR-Related Values • Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus – Internal transmission constraints are addressed through the LSR and MCLs • A LSR will be calculated for the import-constrained Southeast New England (SENE) Capacity Zone, consisting of the NEMA/Boston, SEMA and RI Load Zones • MCLs will be calculated for two export-constrained Capacity Zones: the Maine Capacity Zone and the Northern New England (NNE) Capacity Zone, consisting of the combined Load Zones of Maine, New Hampshire and Vermont – The Maine Capacity Zone will be nested in the NNE Capacity Zone • The MRI based method for calculating demand curves will be used to develop System and Capacity Zone Demand Curves Note: For more info on the development of FCA 15 Capacity Zones, see https://www.iso-ne.com/static- assets/documents/2020/05/a05_pspc_2020_05_28_fca_15_cap_zone_formation.pdf ISO-NE PUBLIC 3 ASSUMPTIONS FOR THE 2024-2025 FCA ICR-RELATED VALUES CALCULATIONS ISO-NE PUBLIC 4 Cost of New Entry (CONE) - for the MRI Demand Curve • CONE for the cap of the MRI system Demand Curve for FCA 15 has been calculated as: – Gross CONE: $11.951/kW-month – Net CONE : $8.707/kW-month – FCA Starting Price : $13.932/kW-month *See link to Forward Capacity Market (FCM) parameters by Capacity Commitment Period: https://www.iso- ne.com/static-assets/documents/2015/09/FCA_Parameters_Final_Table.xlsx ISO-NE PUBLIC 5 Assumptions for the ICR-Related Values Calculations • Load forecast – Net of behind-the-meter (BTM) photovoltaic (PV) forecast – Transportation and heating electrification – Load forecast distribution • Resource data will be based on qualified existing capacity values for FCA 15 – Non-Intermittent Generating Resources – Intermittent Power Resources (IPR) – Import Capacity Resources – Demand Capacity Resources • These qualified capacity values reflect – Significant decrease of existing qualified resources – Resource retirements and terminations • Permanent and Retirement De-List Bids elected unconditional treatment and that are at or above the FCA 15 Starting Price ISO-NE PUBLIC 6 Assumptions for the ICR-Related Values Calculations, cont. • Resource availability – Non-Intermittent Generating Resources availability – IPR availability – ADCR availability • Load relief from Operating Procedure No. 4, Action During a Capacity Deficiency (OP-4) actions – Tie reliability benefits • Quebec • Maritimes • New York – 5% voltage reduction ISO-NE PUBLIC 7 Load Forecast Data • Load forecast assumption from the 2020 Forecast Report of Capacity, Energy, Loads and Transmission (CELT) load forecast* • The load forecast weather-related uncertainty is represented by specifying a series of multipliers on the peak load and the associated probabilities of each load level occurring – The multipliers used to describe the load forecast uncertainty are derived from the 52 weekly peak load distributions described by the expected value (mean), the standard deviation and the skewness *The 2020 CELT load forecast is available at https://www.iso-ne.com/static- assets/documents/2020/04/2020_celt_report.xlsx ISO-NE PUBLIC 8 Load Forecast Data, cont. Modeling of BTM PV • FCA 15 ICR calculations will use an hourly profile of BTM PV corresponding to the load shape for the year 2002, used by the Northeast Power Coordinating Council (NPCC) for reliability studies. For more information on the development of the hourly profile see: https://www.iso-ne.com/static- assets/documents/2017/06/pspc_6_22_2017_2002_PV_profile.pdf – Used for all probabilistic ICR-Related Values calculations – Modeled in GE MARS by groupings using the Regional System Plan (RSP) 13-subarea representation – Includes an 8% transmission and distribution gross-up – Peak load reduction uncertainty is modeled (randomly selected by MARS from a seven day window distribution) • The values of BTM PV published in the 2020 CELT Report are the values of BTM PV subtracted from the gross load forecast to determine the net load forecast • The published 90/10 net load forecast for the SENE sub-areas is used in the TSA Notes: For more info on the PV forecast, see https://www.iso-ne.com/static-assets/documents/2020/04/final_2020_pv_forecast.pdf ISO-NE PUBLIC 9 Load Forecast Data, cont. Modeling of Transportation and Heating Electrification Transportation Electrification – The ICR and Related Values calculations will use an hourly profile for transportation electrification forecast • Includes an 8% transmission and distribution gross-up • Uncertainty is currently not modeled due to lack of performance data – More information on the development of the transportation electrification forecast can be found at : https://www.iso-ne.com/static- assets/documents/2020/04/final_2020_transp_elec_forecast.pdf Heating Electrification – The ICR and Related Values calculations will use the 2020 CELT gross load forecast that include the heating electrification loads which occur during the winter months • The hourly gross load forecast (2020 Forecast Data workbook) is inclusive of heating electrification forecast. The heating electrification loads are weather sensitive and therefore, the uncertainties relating to weather also apply to these loads – More information on the development of the heating electrification forecast can be found at : https://www.iso-ne.com/static- assets/documents/2020/04/final_2020_heat_elec_forecast.pdf ISO-NE PUBLIC 10 Load Forecast Data, cont. New England System Load Forecast Monthly Peak Load (MW) - Net of BTM PV CCP JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY 2024-2025 26,095 28,202 27,426 24,068 19,507 21,190 23,094 24,073 23,383 21,571 19,488 22,756 • Corresponds to the reference forecast labeled “ISO-NE Control Area & New England States Monthly Peak Load Forecast“ from worksheet “4 Mnth Peak” of the 2020 Forecast Data • https://www.iso-ne.com/static-assets/documents/2020/04/forecast_data_2020.xlsx Probability Distribution of Seasonal Peak Load (MW) 10/90 20/80 30/70 40/60 50/50 60/40 70/30 80/20 90/10 95/5 Summer 2024 27,771 28,202 28,581 28,933 29,303 29,836 30,251 30,667 31,377 31,889 Winter 2024-25 23,958 24,073 24,158 24,255 24,329 24,464 24,634 24,814 25,020 25,195 • From Table 1.6 - Seasonal Peak Load Forecast Distributions (forecast is reference with reduction for BTM PV) of the 2020 CELT • https://www.iso-ne.com/static-assets/documents/2020/04/2020_celt_report.xlsx ISO-NE PUBLIC 11 Resource Data – Generating Capacity Resources (MW) Non-Intermittent Generating Resource Intermittent Resource Total Load Zone Summer Winter Summer Winter Summer Winter MAINE 2844.953 3026.457 281.313 329.956 3126.266 3356.413 NEW HAMPSHIRE 4152.612 4306.116 82.170 161.120 4234.782 4467.236 VERMONT 206.814 245.674 64.118 107.785 270.932 353.459 CONNECTICUT 9741.155 10183.737 120.887 99.409 9862.042 10283.146 RHODE ISLAND 1826.126 2025.848 47.318 41.508 1873.444 2067.356 SOUTH EAST MASSACHUSETTS 4460.967 4763.884 289.751 357.617 4750.718 5121.501 WEST CENTRAL MASSACHUSETTS 3740.827 3984.596 173.579 109.119 3914.406 4093.715 NORTH EAST MASSACHUSETTS & BOSTON 1296.241 1399.331 54.483 43.609 1350.724 1442.940 Total New England 28269.695 29935.643 1113.619 1250.123 29383.314 31185.766 Qualified Existing Generating Capacity Resources for FCA 15 reflect: • Significant decreases • Resource retirements and known terminations • Unconditional Permanent and Retirement De-List Bids • Permanent De-List Bids that are at or above the FCA 15 Starting Price • IPR have both summer and winter values modeled; Non-Intermittent Generating Resources winter values provided for informational purpose ISO-NE PUBLIC 12 Resource Data – Import Capacity Resources (MW) Import Resource Summer MW External Interface NYPA - CMR 68.000 New York AC Ties NYPA - VT 14.000 New York AC Ties Total MW 82.000 • Qualified Existing Import Capacity Resources for FCA 15 • The NYPA supplied Import Capacity Resources’ performance (availability) will be modeled with the performance assumptions associated with the New York AC ties ISO-NE PUBLIC 13 Resource Data – Demand Capacity Resources (MW) Seasonal Peak Demand Active Demand Capacity On-Peak Demand Resource Total Load Zone Resource Resource (ADCR) Summer Winter Summer Winter Summer Winter Summer Winter MAINE 224.411 201.876 - - 137.803 155.699 362.214 357.575 NEW HAMPSHIRE 136.625 134.384 - - 48.408 47.688 185.033 182.072 VERMONT 111.485 111.751 - - 51.904 57.510 163.389 169.261 CONNECTICUT 130.311 68.194 561.440 635.793 192.829 192.123 884.580 896.110 RHODE ISLAND 270.390 281.671 - -
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